The present invention relates to the field of flow meters for multiphase mixtures. In particular, the invention relates to flow meters for oil and water mixtures in hydrocarbon boreholes.
The measurement of oil and water flow rate in each producing zone of an oil well is important to the monitoring and control of fluid movement in the well and reservoir. In addition to a flow meter, each zone may have a valve to control the fluid inlet from that zone. By monitoring flow rates of oil and water from each zone and reducing flow from those zones producing the highest water cut (i.e., ratio of water flow rate to total flow rate), the water production of the entire well can be controlled. This, in addition, allows the reservoir oil to be swept more completely during the life of the well.
Ideally, a flow meter in such an installation should satisfy several criteria: 1) it should be extremely reliable and operate for years at downhole temperature and pressure; 2) it should operate in both stratified (near-horizontal) and dispersed flow regimes over a wide range of total flow rate and cut; 3) it should not require that the completion be oriented azimuthally in any particular way during installation; 4) it should not require licensing of radioactive sources and, finally; 5) the flow meter should allow small changes in water cut and flow rate to be detected.
Typically, downhole flow meters determine the holdup (volume fraction of oil or water) and the velocity of the oil phase, the water phase, or both. The flow rate of water is then determined from the product of water holdup xcex1w, the pipe area A, and the velocity of water Uw. An analogous relation holds for oil flow rate. In general, the velocities of water and oil are different. The slip velocity (difference in oil and water velocities) depends on many parameters, such as the inclination angle of the flow pipe (i.e. deviation), roughness of the pipe wall, and flow rates of the two phases. In general, one must measure the holdup and velocities of both oil and water to determine oil and water flow rate uniquely. In practice, sometimes one measures the velocity of only one phase and uses a theoretical or empirically determined slip law to obtain the other. This has a number drawbacks including inaccuracies due to differences conditions used as inputs to the model and the actual conditions downhole.
A common method to determine the velocity of a fluid is to measure the rotation rate of a turbine blade in the flow stream. In single phase flow, the rotational velocity of the turbine is simply related to the velocity of the flow. However, in mixed oil and water flow the response of the turbine can be so complicated as to be uninterpretable.
Another method of velocity measurement uses tracers. A tracer is injected into the phase of choice (oil or water) and, at a known distance downstream, a sensor detects the time of passage of the tracer. The velocity is computed from the known distance and time of travel. One disadvantage of the tracer method for permanent downhole use is the need for a reservoir of tracer material and a mechanical tracer injector. The reservoir limits the number of measurements and the injector, being a mechanical device, is prone to sticking and failure.
Another method of velocity measurement uses local capacitance or resistance sensors. This method is appropriate for flow regimes in which one phase is dispersed as droplets in another continuous phase. As a droplet passes one of the sensors, a signal is produced for a time duration related to the speed of the droplet. Given knowledge of the droplet size by other means, the velocity of the droplet can be deduced. One disadvantage of this method is that it does not work at all in a stratified flow regime, since it relies on the existence of bubbles.
There are other methods of flow measurement that can be used, which are not described herein, but are familiar to those skilled in the art.
Another method of velocity measurement uses a Venturi. In single phase flow, a Venturi generally obeys the Bernoulli equation which relates volumetric flow rate Q to fluid density xcfx81 and pressure drop from the inlet to the throat of the Venturi:                     Q        =                  C          ⁢                                                    2                ⁢                                  xe2x80x83                                ⁢                Δ                ⁢                                  xe2x80x83                                ⁢                                  p                  /                  ρ                                                            (                                                      1                                          A                      throat                      2                                                        -                                      1                                          A                      inlet                      2                                                                      )                                                                        Equation        ⁢                  xe2x80x83                ⁢        1            
where C is the discharge coefficient which is approximately unity but depends on the geometry of the Venturi, xcex94p is the pressure drop from Venturi inlet to throat, and Athroat at and Ainlet are the throat and inlet cross sectional areas, respectively. The same equation can be used to determine the combined oil and water flow rate where the density in this case is the average mixture density in the throat of the Venturi. In practice, the square root in the equation makes it relatively insensitive to errors in both the density and pressure determinations.
A common method to determine the holdup in a flow of oil and water is to measure the average density of the fluid. Since oil at downhole pressure and temperature typically has a density which is smaller than that of water (around 0.7 g/cm3 compared to 1.0 g/cm3), the oil and water holdups xcex1o and xcex1w can be determined proportionately from the mixture density by the relations                               α          o                =                                            ρ              w                        -                          ρ              mix                                                          ρ              w                        -                          ρ              o                                                          Equation        ⁢                  xe2x80x83                ⁢        2                                          α          w                =                                            ρ              mix                        -                          ρ              o                                                          ρ              w                        -                          ρ              o                                                          Equation        ⁢                  xe2x80x83                ⁢        3            
A common method to determine the mixture density is to measure the hydrostatic pressure of a column of fluid with a gradiomanometer. This device relies on having a component of the gravitational force vector along the axis of the flow pipe. This type of device, however, fails when the flow pipe is horizontal because the gravitational force vector is perpendicular to the pipe axis.
Another method to determine holdup uses capacitor plates to measure the bulk dielectric constant of the fluid. This method is used for flow regimes in which the water is dispersed in bubbles within an oil-continuous medium. It fails in stratified flow or in flow regimes in which the oil is dispersed in bubbles within a water-continuous medium.
Another method to determine holdup uses electrodes or an inductive coupling to measure the bulk resistance of the fluid. This method is used for flow regimes in which the oil is dispersed in bubbles within a water-continuous medium. It fails to work properly in stratified flow or in flow regimes in which the water is dispersed in bubbles within an oil-continuous medium.
Another method to determine holdup uses arrays of capacitor plates or resistance electrodes to measure dielectric constant or resistance in the fluid immediately surrounding the sensor. The accuracy of this method depends on the number of sensors in the array. The disadvantages with this method are that small probes are prone to damage and fouling and the probes are invasive to the pipe, preventing other tools or devices from passing by them freely.
Mixers of various types have been used to mix the oil and water, so as to effectively reduce the slip and allow for more accurate determination of the flow rates. Some mixers are simply small orifices in plates of suitable material. Others comprise more elaborate fins having certain twists or curled shapes. There are a number of disadvantages, however, in using conventional mixers when trying to measure the flow rates of oil and water downhole. For example, the mixer often obstructs the borehole, such that it may be difficult to pass certain equipment such as production logging tools, etc. Mixers also can produce unacceptable amounts of pressure loss. Additionally, mixers are prone to excessive wear with age.
It is possible to measure the pressure differential upstream and downstream of a conventional mixer in an attempt to determine the total flow rate of oil and water. This technique, however, has a number of drawbacks. For example, the accuracy of the flow rate determined by this method is likely to be much lower than using a Venturi, and, in general, greatly dependent upon the flow rates. Using a mixer to measure pressure differential can also lead to inaccuracy due to sensitivity to the exact location of pressure measurement. Using a conventional mixer in this fashion would also be prone to problems associated with wear. For example, in an orifice mixer, the relationship between the pressure differential and the velocity could change significantly over time due to slight changes in shape and size of the orifice caused by wear.
U.S. Pat. No. 4,856,344, issued to Hunt, discloses using a Venturi for obtaining a pressure differential and using a gradiomanometer upstream and through the Venturi to measure density. Hunt discloses using an iterative process to estimate the relative flow velocities. Hunt also discloses using a separate upstream step discontinuity to mix the fluids upstream of the gradiomanometer. However, the method disclosed in Hunt is prone to problems associated with relying on estimates of the flow velocities (i.e. a slip model), using separate additional mixers upstream, and using a gradiomanometer (e.g. nonfunctional when pipe is horizontal, and low accuracy when near-horizontal).
U.S. Pat. No. 5,361,632, issued to Magnani, discusses a holdup measurement using a combination of gradiomanometer and gamma-ray densitometer. Thus, the method of Magnani is prone to problems associated with using a gradiomanometer which is not suitable for measurements in near-horizontal pipes. Furthermore, the method obstructs the borehole and would not be suitable for permanent installation.
U.S. Pat. No. 5,661,237, issued to Dussan et al. discusses a holdup measurement using local probes. There is no mention of a Venturi, however. The method obstructs the borehole and would not be suitable for permanent installation.
U.S. Pat. Nos. 5,893,642 and 5,822,390, issued to Hewitt et al. disclose a method of using a mixer to measure flow rates. However, this method suffers from the disadvantages of using a mixer as described above. For example, the mixer obstructs borehole and is not suitable for permanent installation due to problems of wear.
Thus, it is an object of the present invention to provide a flow meter suitable for downhole placement that is extremely reliable and capable of operating for years at downhole temperatures and pressures. It is another object of the invention to provide a flow meter that is capable of operating in both stratified (near-horizontal) and dispersed flow regimes over a wide range of total flow rate and cut. It is another object of the invention to provide a flow meter that does not require that the wellbore be oriented azimuthally in any particular way during installation. It is another object of the invention to provide a flow meter that does not require the use of relatively strong radioactive sources. It is another object of the present invention to provide a flow meter that is capable of detecting small changes in water cut and flow rate. It is another object of the invention to alleviate the problems associated with the use of conventional mixers, including the possible problems associated with measuring the pressure differential upstream and downstream of a conventional mixer. It is another objective of this invention to provide a measurement of a phase transition pressure.
In this invention, we combine a Venturi total volumetric flow rate measurement with a holdup measurement approximately 3-10 pipe diameters downstream of the Venturi. The invention makes use of a flow instability downstream of the Venturi throat. When the oil and water flow accelerates into the throat of the Venturi, the streamlines converge from their upstream value and the pressure drops as the hydrostatic head is converted into kinetic energy. Conversely, as the flow enters the diffuser section the pressure recovers as the flow decelerates. This adverse pressure gradient can lead to separation of the flow within the boundary layer at some position downstream of the throat of the Venturi. That position depends on the geometry of the Venturi, the individual oil and water flow rates, the deviation angle of the pipe to the horizontal, and the densities of the two fluids. The main flow expands beyond the Venturi as a jet of approximately uniform velocity bounded by a free shear layer, and such shear layers are prone to Kelvin-Helmholtz type instabilities that grow and are convected downstream. In the diffuser of the Venturi, an instability such as this grows and perturbs the interface between the two fluids. The amplitude of the instability depends on the geometry of the Venturi, the deviation of the pipe, the densities of the fluids, and the flow rates. An instability of sufficient strength causes the interface to roll up and break with a resulting mixing of the two layers completely across the pipe.
According to the invention, a method of determining the flow rate of a first fluid phase in a pipe containing at least two fluid phases is provided. The fluid phases flow through an upstream pipe, a constriction, which is preferably a Venturi, and a downstream pipe. The differential pressure of the fluid phases is measured such that it can be related to the total flow rate of the fluid phases through the section of pipe. The differential pressure is preferably measured between the upstream pipe and the throat of the Venturi. The volume fraction of the first fluid phase (preferably water) is determined by making a measurement at a location downstream of the constriction where a substantial amount of mixing of the at least two fluid phases is present, which results from the fluid passing through the Venturi. The flow rate of the first fluid (preferably water) is determined by assuming its velocity is substantially the same as that of the other fluid phases.